Not applicable.
Not applicable.
1. Field of the Invention
The invention relates generally to exploration and production, and more particularly, to a method and apparatus for monitoring and detecting kicks and cuttings-bed formation or drill cuttings xe2x80x9cpack-offxe2x80x9d while drilling.
2. Background Art
The characteristics of geological formations are of significant interest in the exploration for and production of subsurface mineral deposits, such as oil and gas. Many characteristics, such as the hydrocarbon volume, porosity, lithology, and permeability of a formation, may be deduced from certain measurable quantities. Among these quantities are the non-invaded resistivity, flushed zone resistivity, and diameter of invasion in a formation. In addition, the resistivity of the mud mixture and the distance from the tool face to the formation through the mud can be determined with resistivity measurements. The quantities are typically measured by logging-while-drilling (xe2x80x9cLWDxe2x80x9d) and wireline tools. The tool carries one or more sources that radiate energy into the formation and receivers that sense the result of the radiation. The detectors measure this result and either transmit the data back uphole or temporarily store it downhole. Typically, once uphole, the data is input to one or more formation evaluation models, which are typically software programs used to evaluate the geological formation from which the data was gathered. Also, the effect of the mud mixture present in front of the tools, between the tool and the formation which is to be evaluated, is typically considered as an undesirable borehole effect, for which measurements have to be corrected.
Formation evaluation models usually assume thick beds within the formation that lie normal to the wellbore. These beds are also assumed to be homogeneous not only in composition, but in structure in all azimuths about the wellbore. Logging tools were traditionally designed and built with these assumptions as a guide. These assumptions simplified modeling the formations, which is valuable from the perspective of computing resources.
Formation evaluation models typically give little regard to the side of the borehole on which the tools measure or to whether the tools are azimuthally focused, because formation properties in all directions are assumed to be the same. This is not a problem in thick beds with bedding normal to the wellbore, i.e., in situations where the formation structure actually matches the assumptions. When the bed is no longer normal to the wellbore, however, the measurements can become quite different from one side of the borehole to the other. Without processing, it is impossible to obtain accurate results when combining azimuthally focused measurements (e.g., a wireline or logging while drilling density measurement) and azimuthally omni-directional measurements (e.g., a wireline or logging while drilling induction resistivity measurement). The azimuthally focused tool may respond to one bed while the azimuthally non-focused tool responds to the average of multiple beds. The geometrical effects of dip must be removed before meaningful processing can proceed.
Fluid distribution is another area that many models ignore. In permeable, dipping formations, invasion of drilling fluid is often asymmetric because of gravity slumping of the filtrate. (xe2x80x9cDippingxe2x80x9d is used herein as a relative term which concerns the relative angle between the wellbore and the bedding plane.) More rigorous two-dimensional interpretation models do include filtrate invasion, but ignore dipping beds and azimuthal variations of the invasion. Azimuthal variations are generally not of concern in vertical wells with bedding normal to the wellbore. However, they become important as beds begin to dip or the well becomes deviated. Such variations can be due to dip and asymmetric filtrate invasion.
Gravity also complicates an evaluation. It segregates invading filtrate from formation fluids if there is a density difference. This is especially pronounced in gas zones with large density contrast. Differential pressure between the mud column and the formation creates the initial invasion, normal to the wellbore. This invasion penetrates the formation only so far before gravity dominates at which point the majority of filtrate begins to flow downward rather than outward. xe2x80x9cDownxe2x80x9d does not have to mean toward the bottom of the hole; it could mean toward one of the sides of the hole, if that is the down direction of the bedding. The higher the vertical permeability the more obvious this effect. The heavier fluid will puddle at the first impermeable layer. This puddling can appear on wireline logs (and LWD logs if sufficient time has elapsed since drilling) as an apparent water leg at the base of thick, highly permeable gas zones, even though those zones produced dry gas.
In vertical wells, thin, low permeability layers, which minimize segregation, often mask the effect. If the spacing between layers is less than the axial resolution of the logging tool, then they will not be detectable. In the case of dipping beds, the segregation effect is more obvious. All of the filtrate that leaves the well eventually migrates down dip, even the filtrate that leaves on the up-dip side of the wellbore. This increases the depth of invasion in one direction, making it more obvious on deeper reading logging tools and it creates azimuthal variations of fluids.
Thus, formation evaluations of deviated wells and wells with dipping beds are a challenge, especially with gas reservoirs. Log responses in these wells are often considered xe2x80x9cunexplainable.xe2x80x9d Asymmetry, fluid distribution, and gravity contribute greatly to this problem because of the assumptions one-dimensional and two-dimensional formation evaluation models embody. Even calibration of logs to core samples can be difficult because of the dramatic changes from axial level to axial level asymmetry can cause.
In addition to evaluating the fluids in the formation, the fluids in the borehole are also of interest. As the degree of deviation of a well builds, there is a proportional increase in the likelihood of cuttings bed build-up in the well bore due to the effects of gravity. Cuttings beds have an adverse impact on the cuttings transport and the downhole pressure. Monitoring cuttings transport has been the subject of much research and has a direct impact on how specific well sections ought to be drilled. Gravity also has additional effects on mud mixtures in deviated wells. Particles in suspension in the mud (for instance barite), can fall out of suspension, and the mud mixture on the high side of the hole, can have different properties than the mud mixture on the low side of the hole. Therefore, if the cuttings and other materials are not maintained in suspension, the cuttings and other materials will rest on the low side of the hole, and the mud mixture, the cuttings and other materials will not be azimuthally homogeneously distributed across the borehole.
Currently, the borehole fluid (xe2x80x9cdrilling mudxe2x80x9d or xe2x80x9cmudxe2x80x9d) is characterized at the surface and its properties are extrapolated to conditions downhole. Factors such as temperature, pressure, and mud composition can vary in both space and time along the borehole. In addition, new mud formulations are continually evolving in the industry.
U.S. Pat. No. 3,688,115, issued to Antkiw, discloses a fluid density measuring device for use in producing oil wells. Density is determined by forcing the well fluid to pass through a chamber in the device. The fluid attenuates a beam of gamma radiation that traverses the chamber, the relative changes in the beam intensity providing a measure of the density in question. Streamlined surfaces and passageways leading into and out of the chamber eliminate turbulent flow conditions within the measuring chamber and thereby establish the basis for a substantially more accurate log of the production fluid density.
U.S. Pat. No. 4,297,575, issued to Smith et al., discloses a method for simultaneously measuring the formation bulk density and the thickness of casing in a cased well borehole. Low energy gamma rays are emitted into the casing and formation in a cased borehole. Two longitudinally spaced detectors detect gamma rays scattered back into the borehole by the casing and surrounding earth materials. The count rate signals from the two detectors are appropriately combined according to predetermined relationships to produce the formation bulk density and the casing thickness, which are recorded as a function of borehole depth.
U.S. Pat. No. 4,412,130, issued to Winters, discloses an apparatus for use within a well for indicating the difference in densities between two well fluids. The apparatus, for use with measurement-while-drilling (MWD) systems, is formed within a drill collar with a source of radiation removably disposed in a wall of the drill collar. At least two radiation detectors are located equidistant from the source of radiation with one detector adjacent an interior central bore through the drill collar and a second detector is adjacent the exterior of the drill collar. Two fluid sample chambers are spaced between the source of radiation and the detectors, respectively; one chamber for diverting fluid from the bore and the other chamber for diverting fluid from the annular space between the drill bore and the drill collar. Suitable circuitry is connected to the detectors for producing a differential signal substantially proportional to the difference in radiation received at the two detectors. The difference in the density between fluid passing through the drill collar and returning through the annular space is detected and indicated by the apparatus for early detection and prevention of blowouts.
U.S. Pat. No. 4,492,865, issued to Murphy et al., discloses a system for detecting changes in drilling fluid density downhole during a drilling operation that includes a radiation source and detector which are arranged in the outer wall of a drill string sub to measure the density of drilling fluids passing between the source and detector. Radiation counts detected downhole are transmitted to the surface by telemetry methods or recorded downhole, where such counts are analyzed to determine the occurrence of fluid influx into the drilling fluid from earth formations. Changes in the density of the mud downhole may indicate the influx of formation fluids into the borehole. Such changes in influx are determinative of formation parameters including surpressures which may lead to the encountering of gas kicks in the borehole. Gas kicks may potentially result in blowouts, which of course are to be avoided if possible. Hydrocarbon shows may also be indicative of producible formation fluids. The radiation source and detector in one embodiment of the system are arranged in the wall of the drill string sub to provide a direct in-line transmission of gamma rays through the drilling fluid.
U.S. Pat. No. 4,698,501, issued to Paske et al., discloses a system for logging subterranean formations for the determination of formation density by using gamma radiation. Gamma ray source and detection means are disposed within a housing adapted for positioning within a borehole for the emission and detection of gamma rays propagating through earth formations and borehole drilling fluid. The gamma ray detection means comprises first and second gamma radiation sensors geometrically disposed within the housing the same longitudinal distance from the gamma ray source and diametrically opposed in a common plane. A formation matrix density output signal is produced in proportion to the output signal from each of the gamma ray sensors and in conjunction with certain constants established by the geometrical configuration of the sensors relative to the gamma ray source and the borehole diameter. Formation density is determined without regard to the radial position of the logging probe within the borehole in a measuring while drilling mode.
U.S. Pat. No. 5,144,126, issued to Perry et al., discloses an apparatus for nuclear logging. Nuclear detectors and electronic components are all mounted in chambers within the sub wall with covers being removably attached to the chambers. A single bus for delivering both power and signals extends through the sub wall between either end of the tool. This bus terminates at a modular ring connector positioned on each tool end. This tool construction (including sub wall mounted sensors and electronics, single power and signal bus, and ring connectors) is also well suited for other formation evaluation tools used in measurement-while-drilling applications.
U.S. Pat. No. 5,469,736, issued to Moake et al., discloses a caliper apparatus and a method for measuring the diameter of a borehole, and the standoff of a drilling tool from the walls of a borehole during a drilling operation. The apparatus includes three or more sensors, such as acoustic transducers arranged circumferentially around a downhole tool or drill collar. The transducers transmit ultrasonic signals to the borehole wall through the drilling fluid surrounding the drillstring and receive reflected signals back from the wall. Travel times for these signals are used to calculate standoff data for each transducer. The standoff measurements may be used to calculate the diameter of the borehole, the eccentricity of the tool in the borehole, and the angle of eccentricity with respect to the transducer position. The eccentricity and angle computations may be used to detect unusual movements of the drillstring in the borehole, such as sticking, banging, and whirling.
U.S. Pat. No. 5,473,158, issued to Holenka et al., discloses a method and apparatus for measuring formation characteristics as a function of angular distance segments about the borehole. The measurement apparatus includes a logging while drilling tool which turns in the borehole while drilling. Such characteristics as bulk density, photoelectric effect (PEF), neutron porosity and ultrasonic standoff are all measured as a function of such angular distance segments where one of such segments is defined to include that portion of a xe2x80x9cdownxe2x80x9d or earth""s gravity vector which is in a radial cross sectional plane of the tool. The measurement is accomplished with either a generally cylindrical tool which generally touches a down or bottom portion of the borehole while the tool rotates in an inclined borehole or with a tool centered by stabilizer blades in the borehole.
U.S. Pat. No. 6,032,102, issued to Wijeyesekera et al., discloses a method and an apparatus for determining the porosity of a geological formation surrounding a cased well. The method further comprises generating neutron pulses that irradiate an area adjacent the well, where neutrons are sensed at a plurality of detectors axially spaced apart from each other and a plurality of neutron detector count rates is acquired. A timing measurement is acquired at one of the spacings to measure a first depth of investigation. A ratio of the neutron detector count rates is acquired to measure a second depth of investigation. An apparent porosity is calculated using the timing measurements and the ratios of neutron count rates. The effect of a well casing on the calculated apparent porosity is determined in response to at least one of the ratio of neutron detector count rates and the timing measurement. A cement annulus is computed based on the ratios of neutron count rates and the timing measurement. A formation porosity is calculated by performing a correction to the apparent porosity for the casing and the cement annulus.
U.S. Pat. No. 6,167,348, issued to Cannon, discloses a method for ascertaining a characteristic of a geological formation surrounding a wellbore. The method comprises first generating a set of data including azimuthal and radial information. A set of parameters indicative of fluid behavior in the formation is determined for each one of at least two azimuths from the generated data. A tool-specific invasion factor is then determined. The characteristic is then determined from the parameters, the azimuthal information, and the invasion factor.
U.S. Pat. No. 6,176,323, issued to Weirich et al., discloses a drilling system for drilling oilfield boreholes or wellbores utilizing a drill string having a drilling assembly conveyed downhole by a tubing (usually a drill pipe or coiled tubing). The drilling assembly includes a bottom hole assembly (BHA) and a drill bit. The bottom hole assembly preferably contains commonly used measurement-while-drilling sensors. The drill string also contains a variety of sensors for determining downhole various properties of the drilling fluid. Sensors are provided to determine density, viscosity, flow rate, clarity, compressibility, pressure and temperature of the drilling fluid at one or more downhole locations. Chemical detection sensors for detecting the presence of gas (methane) and H2S are disposed in the drilling assembly. Sensors for determining fluid density, viscosity, pH, solid content, fluid clarity, fluid compressibility, and a spectroscopy sensor are also disposed in the BHA. Data from such sensors may is processed downhole and/or at the surface. Corrective actions are taken at the surface based upon the downhole measurements, which may require altering the drilling fluid composition, altering the drilling fluid pump rate or shutting down the operation to clean wellbore. The drilling system contains one or more models, which may be stored in memory downhole or at the surface. These models are utilized by the downhole processor and the surface computer to determine desired fluid parameters for continued drilling. The drilling system is dynamic, in that the downhole fluid sensor data is utilized to update models and algorithms during drilling of the wellbore and the updated models are then utilized for continued drilling operations.
U.S. Pat. No. 6,220,371, issued to Sharma et al., discloses a method and apparatus for real time in-situ measuring of the downhole chemical and or physical properties of a core of an earth formation during a coring operation. The method and apparatus comprise several embodiments that may use electromagnetic, acoustic, fluid and differential pressure, temperature, gamma and x-ray, neutron radiation, nuclear magnetic resonance, and mudwater invasion measurements to measure the chemical and or physical properties of the core that may include porosity, bulk density, mineralogy, and fluid saturations. There is a downhole apparatus coupled to an inner and or an outer core barrel near the coring bits with a sensor array coupled to the inner core barrel for real time gathering of the measurements. A controller coupled to the sensor array controls the gathering of the measurements and stores the measurements in a measurement storage unit coupled to the controller for retrieval by a computing device for tomographic analysis.
There remains a need for a technique to measure the properties of the formation and borehole fluid downhole with a single tool in order to detect kicks, cuttings bed build-up, or other problems with the borehole fluid. As applied to LWD, such a technique preferably takes advantage of the tool""s rotation while drilling to scan the formation/mud environment.
A method is disclosed for determining a characteristic of a mud mixture surrounding a drilling tool within an inclined borehole in which a drilling tool is conveyed. The method includes defining a cross-section of the tool which is orthogonal to a longitudinal axis of the tool. A bottom contact point of the cross-section of the tool is determined, which contacts the inclined borehole as the tool rotates in the borehole. The cross-section is separated into at least two segments, where one of the segments is called a bottom segment of the borehole which includes the bottom contact point of the cross-section of the tool with the inclined borehole. The tool is turned in the borehole. Energy is applied into the borehole from an energy source disposed in the tool, as the tool is turning in the borehole. Measurement signals are received at one or more sensors disposed in the tool from circumferentially spaced locations around the borehole, where the measurement signals are in response to returning energy which results from the interaction of the applied energy with the mud mixture and the formation. The measurement signals are associated with a particular segment during the time such signals are produced in response to energy returning from the mud mixture and the formation, depending on the sensor""s geometry and spacing and the kind of energy produced, because the geometry, spacing, and energy type will affect the depth of investigation of the energy produced, as the tool is turning in the borehole. An indication of a characteristic of the mud mixture, substantially free of the effects of the formation, is derived as a function of the measurement signals associated with a plurality of the at least two segments of the borehole. The indications of a characteristic of the mud mixture for the plurality of segments are compared with at least one of each other and a known indication of a characteristic of the mud mixture.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.